U.S. patent application number 16/464102 was filed with the patent office on 2019-12-19 for methods for treating fracture faces in propped fractures using fine particulates.
The applicant listed for this patent is Halliburton Energy Services, Inc.. Invention is credited to Ronald Glen Dusterhoft, Vladimir Nikolayevich Martysevich, Philip D. Nguyen, Loan K. Vo, Kenneth E. Williams.
Application Number | 20190382643 16/464102 |
Document ID | / |
Family ID | 62710737 |
Filed Date | 2019-12-19 |
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United States Patent
Application |
20190382643 |
Kind Code |
A1 |
Nguyen; Philip D. ; et
al. |
December 19, 2019 |
METHODS FOR TREATING FRACTURE FACES IN PROPPED FRACTURES USING FINE
PARTICULATES
Abstract
Methods and compositions for mitigating the embedment of
proppant into fracture faces in subterranean formations are
provided. In some embodiments, the methods comprise: introducing a
treatment fluid into a subterranean formation at or above a
pressure sufficient to create or enhance one or more fractures in
the subterranean formation; introducing an anchoring agent into the
subterranean formation to deposit the anchoring agent on a portion
of a fracture face in the one or more fractures within the
subterranean formation; introducing a first particulate material
comprising fine particulates into the subterranean formation to
attach to the anchoring agent on the portion of the fracture face,
wherein said fine particulates have a mean particle size of up to
about 50 .mu.m; introducing a second particulate material
comprising proppant into the one or more fractures in the
subterranean formation.
Inventors: |
Nguyen; Philip D.; (Houston,
TX) ; Dusterhoft; Ronald Glen; (Katy, TX) ;
Vo; Loan K.; (Houston, TX) ; Williams; Kenneth
E.; (Houston, TX) ; Martysevich; Vladimir
Nikolayevich; (Spring, TX) |
|
Applicant: |
Name |
City |
State |
Country |
Type |
Halliburton Energy Services, Inc. |
Houston |
TX |
US |
|
|
Family ID: |
62710737 |
Appl. No.: |
16/464102 |
Filed: |
December 28, 2016 |
PCT Filed: |
December 28, 2016 |
PCT NO: |
PCT/US2016/068934 |
371 Date: |
May 24, 2019 |
Current U.S.
Class: |
1/1 |
Current CPC
Class: |
C09K 8/80 20130101; C09K
8/92 20130101; C09K 8/572 20130101; C09K 8/5751 20130101; C09K 8/62
20130101; E21B 43/267 20130101; C09K 8/88 20130101; C09K 8/845
20130101 |
International
Class: |
C09K 8/575 20060101
C09K008/575; C09K 8/57 20060101 C09K008/57; C09K 8/84 20060101
C09K008/84 |
Claims
1. A method comprising: introducing a treatment fluid into a
subterranean formation at or above a pressure sufficient to create
or enhance one or more fractures in the subterranean formation;
introducing an anchoring agent into the subterranean formation to
deposit the anchoring agent on a portion of a fracture face in the
one or more fractures within the subterranean formation;
introducing a first particulate material comprising fine
particulates into the subterranean formation to attach to the
anchoring agent on the portion of the fracture face, wherein said
fine particulates have a mean particle size of up to about 50
.mu.m; and introducing a second particulate material comprising
proppant into the one or more fractures in the subterranean
formation.
2. The method of claim 1 wherein the treatment fluid comprises the
anchoring agent.
3. The method of claim 1 wherein the treatment fluid comprises the
proppant.
4. The method of claim 1 further comprising allowing the anchoring
agent to consolidate at least a portion of unconsolidated
particulates in the subterranean formation.
5. The method of claim 1 wherein the anchoring agent is operable to
attach to at least a portion of the fracture face by an
electrostatic charge difference.
6. The method of claim 1 wherein the anchoring agent comprises a
curable resin.
7. The method of claim 1 wherein the anchoring agent is coated onto
at least a portion of the fine particulates.
8. The method of claim 1 wherein the anchoring agent is part of an
emulsion.
9. The method of claim 1 wherein the treatment fluid comprises the
fine particulates.
10. The method of claim 1 wherein the treatment fluid further
comprises a gelling agent.
11. The method of claim 1 wherein the proppant has a particle size
of 5 to 7 times a mean particle size of the fine particulates.
12. The method of claim 1 wherein introducing the second
particulate material into the subterranean formation comprises
introducing proppant of gradually increasing particle sizes into
the subterranean formation.
13. The method of claim 1 wherein the treatment fluid is introduced
into a subterranean formation using one or more pumps.
14. An emulsion comprising: a solid phase comprising fine
particulates, wherein said fine particulates have a mean particle
size of up to about 50 .mu.m; a discontinuous phase comprising a
non-aqueous fluid and an anchoring agent; and a continuous phase
comprising an aqueous fluid; wherein at least a plurality of the
fine particulates are encapsulated or at least partially coated by
the discontinuous phase.
15. The emulsion of claim 14 wherein the anchoring agent comprises
a curable resin.
16. The emulsion of claim 14 wherein the anchoring agent is
operable to attach to at least a portion of a fracture face by an
electrostatic charge difference.
17. The emulsion of claim 14 wherein the anchoring agent is
contained in the non-aqueous fluid.
18. A method comprising: pumping a treatment fluid into a
subterranean formation at or above a pressure sufficient to create
or enhance one or more fractures in the subterranean formation;
pumping an emulsion treatment fluid into the subterranean
formation, the emulsion treatment fluid comprising: an aqueous
continuous phase, a plurality of silica fine particulates having a
mean particle size of about 5 .mu.m in a suspension comprising
xanthan, an anchoring agent comprising a curable epoxy resin, and a
dimer acid; depositing the anchoring agent on a portion of a
fracture face in the one or more fractures within the subterranean
formation; attaching at least a portion of the silica fine
particulates to the anchoring agent on the portion of the fracture
face; and pumping a particulate proppant material into the one or
more fractures in the subterranean formation.
19. The method of claim 18 wherein the aqueous continuous phase
further comprises one or more salts.
20. The method of claim 18 wherein pumping the particulate proppant
material into the subterranean formation comprises pumping proppant
material of gradually increasing particle sizes into the
subterranean formation.
Description
BACKGROUND
[0001] The present disclosure relates to systems and methods for
treating subterranean formations.
[0002] Wells in hydrocarbon-bearing subterranean formations are
often stimulated to facilitate the production of those hydrocarbons
using hydraulic fracturing treatments. In hydraulic fracturing
treatments, a viscous fracturing fluid, which also may function as
a carrier fluid, is pumped into a producing zone at a rate and
pressure such that one or more fractures are formed in the zone. In
order to maintain sufficient conductivity through the fracture, it
is often desirable that the formation surfaces within the fracture
or "fracture faces" be able to resist erosion and/or migration to
prevent the fracture from narrowing or fully closing. Typically,
proppant particulates suspended in a portion of the fracturing
fluid or other fluid are also deposited in the fractures when the
fluid is converted to a thin fluid and returned to the surface.
These proppant particulates serve to prevent the fractures from
fully closing so that conductive channels are formed through which
hydrocarbons can flow.
[0003] Shale formations with ductile characteristics may deform
under high closure stresses, especially when exposed to water. When
this happens, the proppant particulates can become embedded into
the ductile formation or the formation material can invade into the
proppant pack, thus diminishing the propped fracture width.
Production of wells with fracture treatments performed in ductile
shales, such as the Eagle Ford shale play, or many shale plays in
China, may decrease soon after the fracturing treatment at least in
part because of this phenomenon.
BRIEF DESCRIPTION OF THE DRAWINGS
[0004] These drawings illustrate certain aspects of some of the
embodiments of the present disclosure, and should not be used to
limit or define the claims.
[0005] FIG. 1 is a diagram illustrating an example of a fracturing
system that may be used in accordance with certain embodiments of
the present disclosure.
[0006] FIG. 2 is a diagram illustrating an example of a
subterranean formation in which a fracturing operation may be
performed in accordance with certain embodiments of the present
disclosure.
[0007] FIGS. 3A, 3B, 3C, and 3D are diagrams illustrating a portion
of a subterranean formation during a treatment according to certain
embodiments of the present disclosure.
[0008] While embodiments of this disclosure have been depicted,
such embodiments do not imply a limitation on the disclosure, and
no such limitation should be inferred. The subject matter disclosed
is capable of considerable modification, alteration, and
equivalents in form and function, as will occur to those skilled in
the pertinent art and having the benefit of this disclosure. The
depicted and described embodiments of this disclosure are examples
only, and not exhaustive of the scope of the disclosure.
DESCRIPTION OF CERTAIN EMBODIMENTS
[0009] The present disclosure relates to methods for treating
subterranean formations. More particularly, the present disclosure
relates to methods and compositions for mitigating the embedment of
proppant into fracture faces in subterranean formations.
[0010] The present disclosure provides methods for mitigating
proppant embedment using an anchoring agent to attach fine
particulates to a portion of a fracture face in certain
subterranean formations (e.g., ductile or weakly consolidated
formations) before placement of proppant inside the fractures. In
some embodiments, the fine particulates and/or anchoring agent may
form a permeable membrane on the fracture face, which may mitigate
proppant embedment into the fracture face while still permitting
the flow of fluids therethrough. Further, an emulsion composition
comprising fine particulates that are encapsulated, coated, or
partially coated in a discontinuous phase that also comprises
anchoring agent is disclosed for use in treating fracture faces in
the formation.
[0011] Among the many potential advantages to the methods and
compositions of the present disclosure, only some of which are
alluded to herein, the methods and compositions of the present
disclosure can help mitigate proppant embedment into ductile
fracture faces and thereby maintain the effective propped fracture
width for a highly conductive flow path. Also, the methods and
compositions disclosed herein can help to facilitate placement of
fine particulates into subterranean micro-fractures, which increase
the surface area available for hydrocarbon production. Further, the
methods and compositions disclosed herein may enhance the vertical
distribution of the proppant pack. Moreover, the methods and
compositions disclosed herein may provide for more effective
stimulation of soft and/or ductile formations.
[0012] In certain methods of the present disclosure, a treatment
fluid is provided. The treatment fluid is introduced into a
subterranean formation at or above a pressure sufficient to create
or enhance one or more fractures in the subterranean formation. An
anchoring agent is introduced into the subterranean formation. The
anchoring agent becomes deposited on a portion of a fracture face
in the one or more fractures within the subterranean formation. A
first particulate material comprising fine particulates is
introduced into the subterranean formation. The fine particulates
have a mean particle size of up to about 50 .mu.m. The fine
particulates are able to attach to the anchoring agent and/or the
formation particles, which may form a permeable membrane along the
fracture face. After the treatment fluid is introduced into the
subterranean formation, a second particulate material comprising
proppant is introduced into the subterranean formation.
[0013] FIGS. 3A, 3B, 3C, and 3D (with their accompanying
magnifications) illustrate a portion of a fracture in a
subterranean formation as it is treated according to certain
embodiments of the present disclosure. A portion of a fracture 302
is shown in a formation 305. In FIG. 3A, the fracture 302 is shown
prior to treatment, having a fracture face 320 on the inner walls
of the fracture. As shown in FIG. 3B, an anchoring agent 300 is
introduced into the subterranean formation, which is deposited on a
fracture face 320 of the fracture 302. Then, as shown in FIG. 3C,
fine particulates 310 are introduced into the fracture 302 and
attach to the anchoring agent 300 along the fracture face 320. The
fine particulates 310 may form a permeable membrane along at least
a portion of the fracture face 320, which may still permit the flow
of fluids therethrough. In some embodiments, the anchoring agent
and the fine particulates may be introduced together, e.g., as part
of an emulsion, and then be deposited on the fracture face 320 as
described above. Referring now to FIG. 3D, proppant 330 is
introduced into the fracture 302, which may prevent the fractures
from fully closing so that conductive channels are formed through
which hydrocarbons can flow. The treatment method disclosed may
mitigate proppant embedment into the fracture face while still
permitting the flow of fluids through the permeable membrane.
[0014] Treatment fluids can be used in a variety of subterranean
treatment operations. As used herein, the terms "treat,"
"treatment," "treating," and grammatical equivalents thereof refer
to any subterranean operation that uses a fluid in conjunction with
achieving a desired function and/or for a desired purpose. Use of
these terms does not imply any particular action by the treatment
fluid. Illustrative treatment operations can include, for example,
fracturing operations, gravel packing operations, acidizing
operations, scale dissolution and removal, consolidation
operations, and the like. In some embodiments, the treatment fluid
will contain the anchoring agent. In some embodiments, the
treatment fluid will contain the proppant.
[0015] The anchoring agents used in the methods and fluids of the
present disclosure may provide adhesive bonding between formation
surfaces and/or particulates and fine particulates, or may help
consolidate the formation particles themselves. In some
embodiments, the formation of a permeable membrane comprising the
fine particulates can prevent embedment of the proppant within the
formation to reduce the potential negative impact on permeability
and/or fracture conductivity. The anchoring agent can be part of
the fracturing fluid or it can be provided in a separate fluid that
is introduced into the wellbore. The amount of anchoring agent
introduced into the subterranean formation may be determined based
on the fracture face surface area.
[0016] No particular mechanism of attachment is implied by the term
"anchoring agent." In some embodiments according to this
disclosure, the anchoring agent attaches to formation particles and
fine particulates using electrostatic charge differentials. In
another embodiment, the anchoring agent attaches to formation
particles and fine particulates through a chemical reaction.
[0017] A non-exclusive list of possible anchoring agents that may
be used in certain embodiments of this disclosure include, but are
not limited to: resins, tackifiers, silane coupling agents, and any
combinations thereof. Resins that may be suitable for use as
anchoring agents of the present disclosure include all resins known
in the art that are capable of forming a hardened, consolidated
mass. Many such resins are commonly used in subterranean
consolidation operations, and some suitable resins include two
component epoxy based resins, novolak resins, polyepoxide resins,
phenol-aldehyde resins, urea-aldehyde resins, urethane resins,
phenolic resins, furan resins, furan/furfuryl alcohol resins,
phenolic/latex resins, phenol formaldehyde resins, polyester resins
and hybrids and copolymers thereof, polyurethane resins and hybrids
and copolymers thereof, acrylate resins, and mixtures thereof. Some
suitable resins, such as epoxy resins, may be cured with an
internal catalyst or activator so that when pumped down hole, they
may be cured using only time and temperature. Other suitable
resins, such as furan resins generally require a time-delayed
catalyst or an external catalyst to help activate the
polymerization of the resins if the cure temperature is low (e.g.,
less than 250.degree. F.), but will cure under the effect of time
and temperature if the formation temperature is above about
250.degree. F., preferably above about 300.degree. F. It is within
the ability of one skilled in the art, with the benefit of this
disclosure, to select a suitable resin for use in embodiments of
the present disclosure and to determine whether a catalyst is
required to trigger curing.
[0018] In some embodiments, compositions suitable for use as
tackifying agents in the present disclosure may comprise any
compound that, when in liquid form or in a solvent solution, will
form a tacky, non-hardening coating upon a particulate. Tackifying
agents suitable for use in the present disclosure include
non-aqueous tackifying agents; aqueous tackifying agents;
silyl-modified polyamides, and reaction products of an amine and a
phosphate ester. In addition to encouraging particulates to form
aggregates, the use of a tackifying agent may reduce particulate
flow back once the particulates are placed into a subterranean
formation. The tackifying agents are provided in an amount ranging
from about 0.1% to about 5% by weight of the fine particulates,
preferably ranging from about 0.5% to about 2.5% by weight of the
fine particulates.
[0019] One type of tackifying agent suitable for use in the present
disclosure is a non-aqueous tackifying agent. A particularly
preferred group of tackifying agents comprise polyamides that are
liquids or in solution at the temperature of the subterranean
formation such that they are, by themselves, non-hardening when
introduced into the subterranean formation. A particularly
preferred product is a condensation reaction product comprised of
commercially available polyacids and a polyamine. Such commercial
products include compounds such as mixtures of C36 dibasic acids
containing some trimer and higher oligomers and also small amounts
of monomer acids that are reacted with polyamines. Other polyacids
include trimer acids, synthetic acids produced from fatty acids,
maleic anhydride, acrylic acid, and the like. Such acid compounds
are commercially available from companies such as Witco
Corporation, Union Camp, Chemtall, and Emery Industries. The
reaction products are available from, for example, Champion
Technologies, Inc. and Witco Corporation. Additional compounds
which may be used as non-aqueous tackifying compounds include
liquids and solutions of, for example, polyesters, polycarbonates
and polycarbamates, natural resins such as shellac and the
like.
[0020] Non-aqueous tackifying agents suitable for use in the
present disclosure may be either used such that they form
non-hardening coating or they may be combined with a
multifunctional material capable of reacting with the non-aqueous
tackifying agent to form a hardened coating. A "hardened coating"
as used herein means that the reaction of the tackifying compound
with the multifunctional material will result in a substantially
non-flowable reaction product that exhibits a higher compressive
strength in a consolidated agglomerate than the tackifying compound
alone with the particulates. In this instance, the non-aqueous
tackifying agent may function similarly to a hardenable resin.
Multifunctional materials suitable for use in the present
disclosure include, but are not limited to, aldehydes such as
formaldehyde, dialdehydes such as glutaraldehyde, hemiacetals or
aldehyde releasing compounds, diacid halides, dihalides such as
dichlorides and dibromides, polyacid anhydrides such as citric
acid, epoxides, furfuraldehyde, glutaraldehyde or aldehyde
condensates and the like, and combinations thereof. In some
embodiments of the present disclosure, the multifunctional material
may be mixed with the tackifying compound in an amount of from
about 0.01 to about 50 percent by weight of the tackifying compound
to effect formation of the reaction product. In some preferable
embodiments, the compound is present in an amount of from about 0.5
to about 1 percent by weight of the tackifying compound.
[0021] Solvents suitable for use with the non-aqueous tackifying
agents of the present disclosure include any solvent that is
compatible with the non-aqueous tackifying agent and achieves the
desired viscosity effect. The solvents that can be used in the
present disclosure preferably include those having high flash
points (most preferably above about 125.degree. F.). Examples of
solvents suitable for use in the present disclosure include, but
are not limited to, butylglycidyl ether, dipropylene glycol methyl
ether, butyl bottom alcohol, dipropylene glycol dimethyl ether,
diethyleneglycol methyl ether, ethyleneglycol butyl ether,
methanol, butyl alcohol, isopropyl alcohol, diethyleneglycol butyl
ether, propylene carbonate, d'limonene, 2-butoxy ethanol, butyl
acetate, furfuryl acetate, butyl lactate, dimethyl sulfoxide,
dimethyl formamide, fatty acid methyl esters, and combinations
thereof. It is within the ability of one skilled in the art, with
the benefit of this disclosure, to determine whether a solvent is
needed to achieve a viscosity suitable to the subterranean
conditions and, if so, how much.
[0022] Aqueous tackifying agents suitable for use in the present
disclosure are not significantly tacky when placed onto a
particulate, but are capable of being "activated" (that is
destabilized, coalesced and/or reacted) to transform the compound
into a sticky, tackifying compound at a desirable time. Such
activation may occur before, during, or after the aqueous
tackifying agent is placed in the subterranean formation. In some
embodiments, a pretreatment may be first contacted with the surface
of a particulate to prepare it to be coated with an aqueous
tackifying agent. Suitable aqueous tackifying agents are generally
charged polymers that comprise compounds that, when in an aqueous
solvent or solution, will form a non-hardening coating (by itself
or with an activator) and, when placed on a particulate, will
increase the continuous critical resuspension velocity of the
particulate when contacted by a stream of water. The aqueous
tackifying agent may enhance the grain-to-grain contact between the
individual particulates within the formation (be they proppant
particulates, formation fines, or other particulates), helping
bring about the consolidation of the particulates into a cohesive,
flexible, and permeable mass.
[0023] Suitable aqueous tackifying agents include any polymer that
can bind, coagulate, or flocculate a particulate. Also, polymers
that function as pressure sensitive adhesives may be suitable.
Examples of aqueous tackifying agents suitable for use in the
present disclosure include, but are not limited to: acrylic acid
polymers; acrylic acid ester polymers; acrylic acid derivative
polymers; acrylic acid homopolymers; acrylic acid ester
homopolymers (such as poly(methyl acrylate), poly (butyl acrylate),
and poly(2-ethylhexyl acrylate)); acrylic acid ester co-polymers;
methacrylic acid derivative polymers; methacrylic acid
homopolymers; methacrylic acid ester homopolymers (such as
poly(methyl methacrylate), poly(butyl methacrylate), and
poly(2-ethylhexyl methacrylate)); acrylamido-methyl-propane
sulfonate polymers; acrylamido-methyl-propane sulfonate derivative
polymers; acrylamido-methyl-propane sulfonate co-polymers; and
acrylic acid/acrylamido-methyl-propane sulfonate co-polymers,
derivatives thereof, and combinations thereof. The term
"derivative" as used herein refers to any compound that is made
from one of the listed compounds, for example, by replacing one
atom in the base compound with another atom or group of atoms.
[0024] Silyl-modified polyamide compounds suitable for use as a
tackifying agent in the methods of the present disclosure may be
described as substantially self-hardening compositions that are
capable of at least partially adhering to particulates in the
unhardened state, and that are further capable of self-hardening
themselves to a substantially non-tacky state to which individual
particulates such as formation fines will not adhere to, for
example, in formation or proppant pack pore throats. Such
silyl-modified polyamides may be based, for example, on the
reaction product of a silating compound with a polyamide or a
mixture of polyamides. The polyamide or mixture of polyamides may
be one or more polyamide intermediate compounds obtained, for
example, from the reaction of a polyacid (e.g., diacid or higher)
with a polyamine (e.g., diamine or higher) to form a polyamide
polymer with the elimination of water.
[0025] Yet another tackifying agent suitable for use in the present
disclosure is a reaction product of an amine and a phosphate ester.
The ratio of amine to phosphate ester combined to create the
reaction product tackifying agent is preferably from about 1:1 to
about 5:1, more preferably from about 2:1 to about 3:1. In some
embodiments it may be desirable to combine the amine and phosphate
ester in the presence of a solvent, such as methanol.
[0026] In some embodiments, the anchoring agent also acts as a
consolidating agent that hardens the ductile formation. In some
embodiments, a curable resin is combined with a tackifying agent,
for among other reasons, to provide a delayed curable system that
provides some degrees of consolidation or bond strength between the
fine particulates and the formation particles, or between the fine
particulates and the proppant particulates. In some embodiments, an
excess amount of delayed curable resin that has been used to carry
fine particulates is allowed to leak into the ductile formation to
treat the formation material. In these embodiments, the cured resin
solidifies in a portion of the ductile or weakly consolidated
formation material along the fracture surfaces to consolidate
and/or strengthen those materials.
[0027] In some embodiments, the fine particulates can be coated
with the anchoring agent. In some embodiments, the anchoring agent
is part of an emulsion that can be made ahead of time and stored
before use. In some embodiments, the emulsion can be comprised of
an aqueous-based anchoring agent wherein the fine particulates are
encapsulated within an emulsion droplet. In another embodiment, the
emulsion can be comprised of an aqueous-base curable resin wherein
the fine particulates are encapsulated within an emulsion
droplet.
[0028] The fine particulates introduced into the subterranean
formation in the methods of the present disclosure may comprise any
particulate material known in the art of an appropriate particle
size. Examples of fine particulates according to this disclosure
include, but are not limited to, silica, fly ash, ceramic
particles, iron oxide particles, carbon tubes, cellulose fibers,
glass particles, glass fibers and thermoplastic particles. In some
embodiments, the fine particulates can be coated with the anchoring
agent. In the embodiments of the present disclosure, the fine
particulates have a mean particle size of up to about 50 .mu.m.
Nanoparticles, i.e. particles with a diameter of about 1 to 100
nanometers, may be considered fine particulates. The size and/or
size distribution of the fine particulates for a particular
application of the present disclosure may be chosen based on the
size of the formation particles. In some embodiments, the fine
particulates will have a particle size of 5 to 6 times the mean
particle size of the formation particulates. The size of the fine
particulates may be selected to provide effective bridging in
preventing invasion of formation materials into the fine
particulate pack or layer on the fracture face. In some
embodiments, the amount of fine particulates introduced into the
subterranean formation may be determined based on the fracture face
surface area. The amount needed can be estimated based on the
fracture type, and in some embodiments, the amount may be
multiplied by some factor (e.g., two or more) in order to ensure
that any micro-fractures in communication with the primary
fractures are also propped by the fine particulates. In some
embodiments, the fine particulates can be introduced into the
subterranean formation as a component of the treatment fluid that
is introduced at or above a pressure sufficient to create or
enhance one or more fractures in the formation.
[0029] In the methods of the present disclosure, following the
introduction of fine particulates into the subterranean formation,
a second particulate material comprising proppant is introduced
into the subterranean formation. The proppant may comprise any
proppant material known in the art. Examples of proppant materials
that may be suitable in certain embodiments include, but are not
limited to, silica (sand), graded sand, Ottawa sands, Brady sands,
Colorado sands; resin-coated sands; gravels; synthetic organic
particles, nylon pellets, high density plastics,
polytetrafluoroethylenes, rubbers, resins; ceramics,
aluminosilicates; glass; sintered bauxite; quartz; aluminum
pellets; ground or crushed shells of nuts, walnuts, pecans,
almonds, ivory nuts, brazil nuts, and the like; ground or crushed
seed shells (including fruit pits) of seeds of fruits, plums,
peaches, cherries, apricots, and the like; ground or crushed seed
shells of other plants (e.g., maize, corn cobs or corn kernels);
crushed fruit pits or processed wood materials, materials derived
from woods, oak, hickory, walnut, poplar, mahogany, and the like,
including such woods that have been processed by grinding,
chipping, or other techniques for forming particles; or
combinations thereof. In some embodiments, the proppant will have a
particle size distribution of 5-7 times the mean particle size of
the fine particulates. This may provide effective bridging within
the subterranean formation for preventing invasion of formation
materials into the proppant pack. In some embodiments, the particle
size of the proppant introduced into the subterranean formation is
gradually increased from medium- to coarse-sized fracturing sand or
other proppant. The gradual increase in particle size may
facilitate placement of the particles in the dominant fracture and
larger branches. In some embodiments, the proppant can be
introduced into the formation as a component of the fracturing
fluid.
[0030] After the proppant is introduced into the subterranean
formation, the fracture may be allowed to close and hold the
proppant in place between the fracture faces that have been treated
with fine particulates.
[0031] In another aspect of the present disclosure, an emulsion
that may be used to treat a subterranean fracture face, among other
reasons, to mitigate the embedment of proppant in the fracture
face, is disclosed. The emulsion comprises a solid phase comprising
fine particulates. The fine particulates have a mean particle size
of up to about 50 .mu.m. The emulsion further comprises a
discontinuous phase that comprises a non-aqueous fluid and an
anchoring agent. The emulsion further comprises continuous phase is
comprised of an aqueous fluid. In the emulsion, at least a
plurality of the fine particulates are encapsulated by the
discontinuous phase. The anchoring agent contained in the
discontinuous phase and the fine particulates of the solid phase
may form a permeable membrane on the fracture face when the
emulsion is introduced into a subterranean formation.
[0032] The treatment fluids used in the methods and systems of the
present disclosure may comprise any base fluid known in the art,
including aqueous base fluids, non-aqueous base fluids, and any
combinations thereof. The term "base fluid" refers to the major
component of the fluid (as opposed to components dissolved and/or
suspended therein), and does not indicate any particular condition
or property of that fluids such as its mass, amount, pH, etc.
Aqueous fluids that may be suitable for use in the methods and
systems of the present disclosure may comprise water from any
source. Such aqueous fluids may comprise fresh water, salt water
(e.g., water containing one or more salts dissolved therein), brine
(e.g., saturated salt water), seawater, or any combination thereof.
In most embodiments of the present disclosure, the aqueous fluids
comprise one or more ionic species, such as those formed by salts
dissolved in water. For example, seawater and/or produced water may
comprise a variety of divalent cationic species dissolved therein.
In certain embodiments, the density of the aqueous fluid can be
adjusted, among other purposes, to provide additional particulate
transport and suspension in the compositions of the present
disclosure. In certain embodiments, the pH of the aqueous fluid may
be adjusted (e.g., by a buffer or other pH adjusting agent) to a
specific level, which may depend on, among other factors, the types
of viscosifying agents, acids, and other additives included in the
fluid. One of ordinary skill in the art, with the benefit of this
disclosure, will recognize when such density and/or pH adjustments
are appropriate. Examples of non-aqueous fluids that may be
suitable for use in the methods and systems of the present
disclosure include, but are not limited to, oils, hydrocarbons,
organic liquids, and the like. In certain embodiments, the
fracturing fluids may comprise a mixture of one or more fluids
and/or gases, including but not limited to emulsions, foams, and
the like.
[0033] In certain embodiments, the treatment fluids used in the
methods and compositions of the present disclosure optionally may
comprise any number of additional additives. Examples of such
additional additives include, but are not limited to, salts,
surfactants, acids, spacers, diverting agents, fluid loss control
additives, gas, nitrogen, carbon dioxide, surface modifying agents,
gelling agents, foamers, corrosion inhibitors, scale inhibitors,
catalysts, clay control agents, biocides, friction reducers,
antifoam agents, bridging agents, flocculants, additional H.sub.2S
scavengers, CO.sub.2 scavengers, oxygen scavengers, lubricants,
additional viscosifiers, breakers, weighting agents, relative
permeability modifiers, resins, wetting agents, coating enhancement
agents, filter cake removal agents, antifreeze agents (e.g.,
ethylene glycol), and the like. In certain embodiments, one or more
of these additional additives (e.g., a crosslinking agent) may be
added to the treatment fluid and/or activated after the
viscosifying agent has been at least partially hydrated in the
fluid. A person skilled in the art, with the benefit of this
disclosure, will recognize the types of additives that may be
included in the fluids of the present disclosure for a particular
application.
[0034] The treatment fluids and/or emulsions of the present
disclosure may be prepared using any suitable method and/or
equipment (e.g., blenders, mixers, stirrers, etc.) known in the art
at any time prior to their use. The treatment fluids and/or
emulsions may be prepared at least in part at a well site or at an
offsite location. In certain embodiments, the treatment fluids can
be introduced in a dry or slurried state. In certain embodiments,
the anchoring agent and/or other components of the treatment fluid
and/or emulsion may be metered directly into a base treatment fluid
to form a treatment fluid. In certain embodiments, the base fluid
may be mixed with the fine particulates and/or other components of
the treatment fluid and/or emulsion at a well site where the
operation or treatment is conducted, either by batch mixing or
continuous ("on-the-fly") mixing. The term "on-the-fly" is used
herein to include methods of combining two or more components
wherein a flowing stream of one element is continuously introduced
into a flowing stream of another component so that the streams are
combined and mixed while continuing to flow as a single stream as
part of the on-going treatment. Such mixing can also be described
as "real-time" mixing. In other embodiments, the treatment fluids
or emulsions of the present disclosure may be prepared, either in
whole or in part, at an offsite location and transported to the
site where the treatment or operation is conducted. In introducing
a treatment fluid of the present disclosure into a portion of a
subterranean formation, the components of the treatment fluid may
be mixed together at the surface and introduced into the formation
together, or one or more components may be introduced into the
formation at the surface separately from other components such that
the components mix or intermingle in a portion of the formation to
form a treatment fluid. In either such case, the treatment fluid is
deemed to be introduced into at least a portion of the subterranean
formation for purposes of the present disclosure.
[0035] The present disclosure provides methods for using the
treatment fluids to carry out hydraulic fracturing treatments. In
certain embodiments, one or more treatment fluids (e.g., pad
fluids, pre-pad fluids, other fluids) may be introduced into a
subterranean formation, for example, through a well bore that
penetrates a subterranean formation. In these embodiments, one or
more of the treatment fluids may be introduced at a pressure
sufficient to create or enhance one or more fractures within the
subterranean formation.
[0036] Certain embodiments of the methods and compositions
disclosed herein may directly or indirectly affect one or more
components or pieces of equipment associated with the preparation,
delivery, recapture, recycling, reuse, and/or disposal of the
disclosed compositions. For example, and with reference to FIG. 1,
the disclosed methods and compositions may directly or indirectly
affect one or more components or pieces of equipment associated
with an exemplary fracturing system 10, according to one or more
embodiments. In certain instances, the system 10 includes a
fracturing fluid producing apparatus 20, a fluid source 30, a
proppant source 40, and a pump and blender system 50 and resides at
the surface at a well site where a well 60 is located. In certain
instances, the fracturing fluid producing apparatus 20 combines a
gel pre-cursor with fluid (e.g., liquid or substantially liquid)
from fluid source 30, to produce a hydrated fracturing fluid that
is used to fracture the formation. The hydrated fracturing fluid
can be a fluid for ready use in a fracture stimulation treatment of
the well 60 or a concentrate to which additional fluid is added
prior to use in a fracture stimulation of the well 60. In other
instances, the fracturing fluid producing apparatus 20 can be
omitted and the fracturing fluid sourced directly from the fluid
source 30. In certain instances, the fracturing fluid may comprise
water, a hydrocarbon fluid, a polymer gel, foam, air, wet gases
and/or other fluids.
[0037] The proppant source 40 can include a proppant for
combination with the fracturing fluid. The system may also include
additive source 70 that provides one or more additives (e.g.,
gelling agents, weighting agents, and/or other optional additives)
to alter the properties of the treatment fluid. For example, the
other additives 70 can be included to reduce pumping friction, to
reduce or eliminate the fluid's reaction to the geological
formation in which the well is formed, to operate as surfactants,
and/or to serve other functions.
[0038] The pump and blender system 50 receives the fracturing fluid
and combines it with other components, including proppant from the
proppant source 40 and/or additional fluid from the additives 70.
The resulting mixture may be pumped down the well 60 under a
pressure sufficient to create or enhance one or more fractures in a
subterranean zone, for example, to stimulate production of fluids
from the zone. Notably, in certain instances, the fracturing fluid
producing apparatus 20, fluid source 30, and/or proppant source 40
may be equipped with one or more metering devices (not shown) to
control the flow of fluids, proppants, and/or other compositions to
the pumping and blender system 50. Such metering devices may permit
the pumping and blender system 50 can source from one, some or all
of the different sources at a given time, and may facilitate the
preparation of fracturing fluids in accordance with the present
disclosure using continuous mixing or "on-the-fly" methods. Thus,
for example, the pumping and blender system 50 can provide just
fracturing fluid into the well at some times, just proppants at
other times, and combinations of those components at yet other
times.
[0039] FIG. 2 shows the well 60 during a fracturing operation in a
portion of a subterranean formation of interest 102 surrounding a
well bore 104. The well bore 104 extends from the surface 106, and
the fracturing fluid 108 is applied to a portion of the
subterranean formation 102 surrounding the horizontal portion of
the well bore. Although shown as vertical deviating to horizontal,
the well bore 104 may include horizontal, vertical, slant, curved,
and other types of well bore geometries and orientations, and the
fracturing treatment may be applied to a subterranean zone
surrounding any portion of the well bore. The well bore 104 can
include a casing 110 that is cemented or otherwise secured to the
well bore wall. The well bore 104 can be uncased or include uncased
sections. Perforations can be formed in the casing 110 to allow
fracturing fluids and/or other materials to flow into the
subterranean formation 102. In cased wells, perforations can be
formed using shape charges, a perforating gun, hydro-jetting and/or
other tools.
[0040] The well is shown with a work string 112 depending from the
surface 106 into the well bore 104. The pump and blender system 50
is coupled a work string 112 to pump the fracturing fluid 108 into
the well bore 104. The working string 112 may include coiled
tubing, jointed pipe, and/or other structures that allow fluid to
flow into the well bore 104. The working string 112 can include
flow control devices, bypass valves, ports, and or other tools or
well devices that control a flow of fluid from the interior of the
working string 112 into the subterranean zone 102. For example, the
working string 112 may include ports adjacent the well bore wall to
communicate the fracturing fluid 108 directly into the subterranean
formation 102, and/or the working string 112 may include ports that
are spaced apart from the well bore wall to communicate the
fracturing fluid 108 into an annulus in the well bore between the
working string 112 and the well bore wall.
[0041] The working string 112 and/or the well bore 104 may include
one or more sets of packers 114 that seal the annulus between the
working string 112 and well bore 104 to define an interval of the
well bore 104 into which the fracturing fluid 108 will be pumped.
FIG. 2 shows two packers 114, one defining an uphole boundary of
the interval and one defining the downhole end of the interval.
When the fracturing fluid 108 is introduced into well bore 104
(e.g., in FIG. 2, the area of the well bore 104 between packers
114) at a sufficient hydraulic pressure, one or more fractures 116
may be created in the subterranean zone 102. The proppant
particulates in the fracturing fluid 108 may enter the fractures
116 where they may remain after the fracturing fluid flows out of
the well bore. These proppant particulates may "prop" fractures 116
such that fluids may flow more freely through the fractures
116.
[0042] While not specifically illustrated herein, the disclosed
methods and compositions may also directly or indirectly affect any
transport or delivery equipment used to convey the compositions to
the fracturing system 10 such as, for example, any transport
vessels, conduits, pipelines, trucks, tubulars, and/or pipes used
to fluidically move the compositions from one location to another,
any pumps, compressors, or motors used to drive the compositions
into motion, any valves or related joints used to regulate the
pressure or flow rate of the compositions, and any sensors (i.e.,
pressure and temperature), gauges, and/or combinations thereof, and
the like.
[0043] To facilitate a better understanding of the present
disclosure, the following examples of certain aspects of certain
embodiments are given. The following examples are not the only
examples that could be given according to the present disclosure
and are not intended to limit the scope of the disclosure or
claims.
EXAMPLE
[0044] A mixture containing water as a carrier fluid, 50 gpt of a
slurry containing silica fines (d50.about.5 .mu.m) in a xanthan
suspension and 50 gpt of aqueous external emulsion of Rhemod.TM. L
viscosifier was prepared. Rhemod.TM. L viscosifier is a dimer acid
that is only soluble in organic acid, available from Halliburton
Energy Services, Inc. Forming an aqueous external emulsion of
Rhemod.TM. L viscosifier allows it to be dispersible in an aqueous
carrier fluid such as water or brine. The mixture appeared to be
fully stable with the silica fines and Rhemod.TM. L viscosifier
emulsion completely dispersed in the water. A 50 gpt of
Sandtrap.RTM. ABC part A resin was added to the mixture.
Sandtrap.RTM. ABC part A curable epoxy resin is available from
Halliburton Energy Services, Inc. A curing reaction occurred when
Sandtrap.RTM. ABC part A resin was exposed to the mixture
containing Rhemod.TM. L viscosifier.
[0045] An Eagle Ford shale core was split into two halves to create
a simulated fracture face. One half of the split core was submerged
into a solution of 5% KCl, to be used as a comparsion. The other
half of the split core was submerged into the mixture containing a
5% KCl solution, silica fines, Rhemod.TM. L viscosifier, and
Sandtrap.RTM. ABC part A resin, and the fracture face was treated.
In this mixture, Rhemod.TM. L viscosifier acted as a hardening
agent that also offers some tackiness, and helps the silica fines
to adhere to the fracture face. After 5 minutes of treatment, the
treated half-core was placed in an oven for curing at 200.degree.
F. for 6 hours. Scanning electron microscopy pictures of the
treated fracture face showed silica fines adhered onto the fracture
face. The Brinell Hardness (BHN) of each half of the split core was
then measured, which demonstrated the alteration of the hardness of
the fracture face upon treatment.
TABLE-US-00001 Untreated BHN Treated BHN (Kgf/mm.sup.2)
(Kgf/mm.sup.2) Eagle Ford 92 118
[0046] An embodiment of the present disclosure is a method
comprising: introducing a treatment fluid into a subterranean
formation at or above a pressure sufficient to create or enhance
one or more fractures in the subterranean formation; introducing an
anchoring agent into the subterranean formation to deposit the
anchoring agent on a portion of a fracture face in the one or more
fractures within the subterranean formation; introducing a first
particulate material comprising fine particulates into the
subterranean formation to attach to the anchoring agent on the
portion of the fracture face, wherein said fine particulates have a
mean particle size of up to about 50 .mu.m; and introducing a
second particulate material comprising proppant into the one or
more fractures in the subterranean formation.
[0047] Another embodiment of the present disclosure is a system
comprising: an emulsion comprising a solid phase comprising fine
particulates, wherein said fine particulates have a mean particle
size of up to about 50 .mu.m; a discontinuous phase comprising a
non-aqueous fluid and an anchoring agent; a continuous phase
comprising an aqueous fluid; and wherein at least a plurality of
the fine particulates are encapsulated, coated, or at least
partially coated by the discontinuous phase.
[0048] Another embodiment of the present disclosure is a method
comprising: pumping a treatment fluid into a subterranean formation
at or above a pressure sufficient to create or enhance one or more
fractures in the subterranean formation; pumping an emulsion
treatment fluid into the subterranean formation, the emulsion
treatment fluid comprising: an aqueous continuous phase, a
plurality of silica fine particulates having a mean particle size
of about 5 .mu.m in a suspension comprising xanthan, an anchoring
agent comprising a curable epoxy resin, and a dimer acid;
depositing the anchoring agent on a portion of a fracture face in
the one or more fractures within the subterranean formation;
attaching at least a portion of the silica fine particulates to the
anchoring agent on the portion of the fracture face; and pumping a
particulate proppant material into the one or more fractures in the
subterranean formation.
[0049] Therefore, the present disclosure is well adapted to attain
the ends and advantages mentioned as well as those that are
inherent therein. The particular embodiments disclosed above are
illustrative only, as the present disclosure may be modified and
practiced in different but equivalent manners apparent to those
skilled in the art having the benefit of the teachings herein.
While numerous changes may be made by those skilled in the art,
such changes are encompassed within the spirit of the subject
matter defined by the appended claims. Furthermore, no limitations
are intended to the details of construction or design herein shown,
other than as described in the claims below. It is therefore
evident that the particular illustrative embodiments disclosed
above may be altered or modified and all such variations are
considered within the scope and spirit of the present disclosure.
In particular, every range of values (e.g., "from about a to about
b," or, equivalently, "from approximately a to b," or,
equivalently, "from approximately a-b") disclosed herein is to be
understood as referring to the power set (the set of all subsets)
of the respective range of values. The terms in the claims have
their plain, ordinary meaning unless otherwise explicitly and
clearly defined by the patentee.
* * * * *